1. Field of the Invention
The present invention relates generally to methods and systems for production of hydrocarbons, hydrogen, and/or other products from various relatively low permeability formations containing heavy hydrocarbons. Certain embodiments relate to in situ conversion of hydrocarbons to produce hydrocarbons, hydrogen, and/or novel product streams from underground relatively low permeability formations containing heavy hydrocarbons.
2. Description of Related Art
Hydrocarbons obtained from subterranean (e.g., sedimentary) formations are often used as energy resources, as feedstocks, and as consumer products. Concerns over depletion of available hydrocarbon resources and over declining overall quality of produced hydrocarbons have led to development of processes for more efficient recovery, processing and/or use of available hydrocarbon resources. In situ processes may be used to remove hydrocarbon materials from subterranean formations. Chemical and/or physical properties of hydrocarbon material within a subterranean formation may need to be changed to allow hydrocarbon material to be more easily removed from the subterranean formation. The chemical and physical changes may include in situ reactions that produce removable fluids, composition changes, solubility changes, density changes, phase changes, and/or viscosity changes of the hydrocarbon material within the formation. A fluid may be, but is not limited to, a gas, a liquid, an emulsion, a slurry, and/or a stream of solid particles that has flow characteristics similar to liquid flow.
Examples of in situ processes utilizing downhole heaters are illustrated in U.S. Pat. Nos. 2,634,961 to Ljungstrom, 2,732,195 to Ljungstrom, 2,780,450 to Ljungstrom, 2,789,805 to Ljungstrom, 2,923,535 to Ljungstrom, and U.S. Pat. No. 4,886,118 to Van Meurs et al., each of which is incorporated by reference as if fully set forth herein.
A heat source may be used to heat a subterranean formation. Electric heaters may be used to heat the subterranean formation by radiation and/or conduction. An electric heater may resistively heat an element. U.S. Pat. No. 2,548,360 to Germain, which is incorporated by reference as if fully set forth herein, describes an electric heating element placed within a viscous oil within a wellbore. The heater element heats and thins the oil to allow the oil to be pumped from the wellbore. U.S. Pat. No. 4,716,960 to Eastlund et al., which is incorporated by reference as if fully set forth herein, describes electrically heating tubing of a petroleum well by passing a relatively low voltage current through the tubing to prevent formation of solids. U.S. Pat. No. 5,065,818 to Van Egmond, which is incorporated by reference as if fully set forth herein, describes an electric heating element that is cemented into a well borehole without a casing surrounding the heating element.
U.S. Pat. No. 6,023,554 to Vinegar et al., which is incorporated by reference as if fully set forth herein, describes an electric heating element that is positioned within a casing. The heating element generates radiant energy that heats the casing. A granular solid fill material may be placed between the casing and the formation. The casing may conductively heat the fill material, which in turn conductively heats the formation.
U.S. Pat. No. 4,570,715 to Van Meurs et al., which is incorporated by reference as if fully set forth herein, describes an electric heating element. The heating element has an electrically conductive core, a surrounding layer of insulating material, and a surrounding metallic sheath. The conductive core may have a relatively low resistance at high temperatures. The insulating material may have electrical resistance, compressive strength, and heat conductivity properties that are relatively high at high temperatures. The insulating layer may inhibit arcing from the core to the metallic sheath. The metallic sheath may have tensile strength and creep resistance properties that are relatively high at high temperatures.
U.S. Pat. No. 5,060,287 to Van Egmond, which is incorporated by reference as if fully set forth herein, describes an electrical heating element having a copper-nickel alloy core.
Combustion of a fuel may be used to heat a formation. Combusting a fuel to heat a formation may be more economical than using electricity to heat a formation. Several different types of heaters may use fuel combustion as a heat source that heats a formation. The combustion may take place in the formation, in a well, and/or near the surface. Combustion in the formation may be a fireflood. An oxidizer may be pumped into the formation. The oxidizer may be ignited to advance a fire front towards a production well. Oxidizer pumped into the formation may flow through the formation along fracture lines in the formation. Ignition of the oxidizer may not result in the fire front flowing uniformly through the formation.
A flameless combustor may be used to combust a fuel within a well. U.S. Pat. No. 5,255,742 to Mikus, U.S. Pat. No. 5,404,952 to Vinegar et al., U.S. Pat. No. 5,862,858 to Wellington et al., and U.S. Pat. No. 5,899,269 to Wellington et al., which are incorporated by reference as if fully set forth herein, describe Blameless combustors. Flameless combustion may be accomplished by preheating a fuel and combustion air to a temperature above an auto-ignition temperature of the mixture. The fuel and combustion air may be mixed in a heating zone to combust. In the heating zone of the flameless combustor, a catalytic surface may be provided to lower the auto-ignition temperature of the fuel and air mixture.
Heat may be supplied to a formation from a surface heater. The surface heater may produce combustion gases that are circulated through wellbores to heat the formation. Alternately, a surface burner may be used to heat a heat transfer fluid that is passed through a wellbore to heat the formation. Examples of fired heaters, or surface burners that may be used to heat a subterranean formation, are illustrated in U.S. Pat. No. 6,056,057 to Vinegar et al. and U.S. Pat. No. 6,079,499 to Mikus et al., which are both incorporated by reference as if fully set forth herein.
Synthesis gas may be produced in reactors or in situ within a subterranean formation. Synthesis gas may be produced within a reactor by partially oxidizing methane with oxygen. In situ production of synthesis gas may be economically desirable to avoid the expense of building, operating, and maintaining a surface synthesis gas production facility. U.S. Pat. No. 4,250,230 to Terry, which is incorporated by reference as if fully set forth herein, describes a system for in situ gasification of coal. A subterranean coal seam is burned from a first well towards a production well. Methane, hydrocarbons, H2, CO, and other fluids may be removed from the formation through the production well. The H2 and CO may be separated from the remaining fluid. The H2 and CO may be sent to fuel cells to generate electricity.
U.S. Pat. No. 4,057,293 to Garrett, which is incorporated by reference as if fully set forth herein, discloses a process for producing synthesis gas. A portion of a rubble pile is burned to heat the rubble pile to a temperature that generates liquid and gaseous hydrocarbons by pyrolysis. After pyrolysis, the rubble is further heated, and steam or steam and air are introduced to the rubble pile to generate synthesis gas.
U.S. Pat. No. 5,554,453 to Steinfeld et al., which is incorporated by reference as if fully set forth herein, describes an ex situ coal gasifier that supplies fuel gas to a fuel cell. The fuel cell produces electricity. A catalytic burner is used to burn exhaust gas from the fuel cell with an oxidant gas to generate heat in the gasifier.
Carbon dioxide may be produced from combustion of fuel and from many chemical processes. Carbon dioxide may be used for various purposes, such as, but not limited to, a feed stream for a dry ice production facility, supercritical fluid in a low temperature supercritical fluid process, a flooding agent for coal bed demethanation, and a flooding agent for enhanced oil recovery. Although some carbon dioxide is productively used, many tons of carbon dioxide are vented to the atmosphere.
U.S. Pat. No. 2,780,450 to Ljungstrom describes heating bituminous geological formations in situ to convert or crack a liquid tar-like substance into oils and gases.
U.S. Pat. No. 4,597,441 to Ware et al., which is incorporated by reference as if fully set forth herein, describes contacting oil, heat, and hydrogen simultaneously in a reservoir. Hydrogenation may enhance recovery of oil from the reservoir.
U.S. Pat. No. 5,046,559 to Glandt and 5,060,726 to Glandt et al., are incorporated by reference as if fully set forth herein.
Substantial reserves of heavy hydrocarbons are known to exist in formations that have relatively low permeability. For example, billions of barrels of oil reserves are known to exist in diatomaceous formations in California. Several methods have been proposed and/or used for producing heavy hydrocarbons from relatively low permeability formations.
U.S. Pat. No. 5,415,231 to Northrop et al., which is incorporated by reference as if fully set forth herein, describes a method for recovering hydrocarbons (e.g., oil) from a low permeability subterranean reservoir of the type comprised primarily of diatomite. A first slug or volume of a heated fluid (e.g., 60% quality steam) is injected into the reservoir at a pressure greater than the fracturing pressure of the reservoir. The well is then shut in and the reservoir is allowed to soak for a prescribed period (e.g., 10 days or more) to allow the oil to be displaced by the steam into the fractures. The well is then produced until the production rate drops below an economical level. A second slug of steam is then injected and the cycles are repeated.
U.S. Pat. No. 4,530,401 to Hartman et al., which is incorporated by reference as if fully set forth herein, describes a method for the recovery of viscous oil from a subterranean, viscous oil-containing formation by injecting steam into the formation.
U.S. Pat. No. 5,339,897 to Leaute et al. describes a method and apparatus for recovering and/or upgrading hydrocarbons utilizing in situ combustion and horizontal wells.
U.S. Pat. No. 5,431,224 to Laali, which is incorporated by reference as if fully set forth herein, describes a method for improving hydrocarbon flow from low permeability tight reservoir rock.
U.S. Pat. Nos. 5,297,626 Vinegar et al. and 5,392,854 to Vinegar et al., which are incorporated by reference as if fully set forth herein, describe a process wherein an oil containing subterranean formation is heated. The following patents are incorporated herein by reference: U.S. Pat. No. 6,152,987 to Ma et al.; U.S. Pat. No. 5,525,322 to Willms; U.S. Pat. No. 5,861,137 to Edlund; and U.S. Pat. No. 5,229,102 to Minet et al.
As outlined above, there has been a significant amount of effort to develop methods and systems to economically produce hydrocarbons, hydrogen, and/or other products from relatively low permeability formations containing heavy hydrocarbons. At present, however, there are still many relatively low permeability formations containing heavy hydrocarbons from which hydrocarbons, hydrogen, and/or other products cannot be economically produced. Thus, there is still a need for improved methods and systems for production of hydrocarbons, hydrogen, and/or other products from various relatively low permeability formations containing heavy hydrocarbons.
In an embodiment, hydrocarbons within a relatively low permeability formation containing heavy hydrocarbons may be converted in situ within the formation to yield a mixture of relatively high quality hydrocarbon products, hydrogen, and/or other products. One or more heat sources may be used to heat a portion of the relatively low permeability formation containing heavy hydrocarbons to temperatures that allow pyrolysis of the hydrocarbons. Hydrocarbons, hydrogen, and other formation fluids may be removed from the formation through one or more production wells. In some embodiments, formation fluids may be removed in a vapor phase. In other embodiments, formation fluids may be removed in liquid and vapor phases or in a liquid phase. Temperature and pressure in at least a portion of the formation may be controlled during pyrolysis to yield improved products from the formation.
In an embodiment, one or more heat sources may be installed into a formation to heat the formation. Heat sources may be installed by drilling openings (well bores) into the formation. In some embodiments, openings may be formed in the formation using a drill with a steerable motor and an accelerometer. Alternatively, an opening may be formed into the formation by geosteered drilling. Alternately, an opening may be formed into the formation by sonic drilling.
One or more heat sources may be disposed within the opening such that the heat sources transfer heat to the formation. For example, a heat source may be placed in an open wellbore in the formation. Heat may conductively and radiatively transfer from the heat source to the formation. Alternatively, a heat source may be placed within a heater well that may be packed with gravel, sand, and/or cement. The cement may be a refractory cement.
In some embodiments, one or more heat sources may be placed in a pattern within the formation. For example, in one embodiment, an in situ conversion process for hydrocarbons may include heating at least a portion of a relatively low permeability formation containing heavy hydrocarbons with an array of heat sources disposed within the formation. In some embodiments, the array of heat sources can be positioned substantially equidistant from a production well. Certain patterns (e.g., triangular arrays, hexagonal arrays, or other array patterns) may be more desirable for specific applications. In addition, the array of heat sources may be disposed such that a distance between each heat source may be less than about 70 feet (21 m). In addition, the in situ conversion process for hydrocarbons may include heating at least a portion of the formation with heat sources disposed substantially parallel to a boundary of the hydrocarbons. Regardless of the arrangement of or distance between the heat sources, in certain embodiments, a ratio of heat sources to production wells disposed within a formation may be greater than about 3, 5, 8, 10, 20, or more.
Certain embodiments may also include allowing heat to transfer from one or more of the heat sources to a selected section of the heated portion. In an embodiment, the selected section may be disposed between one or more heat sources. For example, the in situ conversion process may also include allowing heat to transfer from one or more heat sources to a selected section of the formation such that heat from one or more of the heat sources pyrolyzes at least some hydrocarbons within the selected section. The in situ conversion process may include heating at least a portion of a relatively low permeability formation containing heavy hydrocarbons above a pyrolyzation temperature of hydrocarbons in the formation. For example, a pyrolyzation temperature may include a temperature of at least about 270xc2x0 C. Heat may be allowed to transfer from one or more of the heat sources to the selected section substantially by conduction.
One or more heat sources may be located within the formation such that superposition of heat produced from one or more heat sources may occur. Superposition of heat may increase a temperature of the selected section to a temperature sufficient for pyrolysis of at least some of the hydrocarbons within the selected section. Superposition of heat may vary depending on, for example, a spacing between heat sources. The spacing between heat sources may be selected to optimize heating of the section selected for treatment. Therefore, hydrocarbons may be pyrolyzed within a larger area of the portion. Spacing between heat sources may be selected to increase the effectiveness of the heat sources, thereby increasing the economic viability of a selected in situ conversion process for hydrocarbons. Superposition of heat tends to increase the uniformity of heat distribution in the section of the formation selected for treatment.
Various systems and methods may be used to provide heat sources. In an embodiment, a natural distributed combustor system and method may heat at least a portion of a relatively low permeability formation containing heavy hydrocarbons. The system and method may first include heating a first portion of the formation to a temperature sufficient to support oxidation of at least some of the hydrocarbons therein. One or more conduits may be disposed within one or more openings. One or more of the conduits may provide an oxidizing fluid from an oxidizing fluid source into an opening in the formation. The oxidizing fluid may oxidize at least a portion of the hydrocarbons at a reaction zone within the formation. Oxidation may generate heat at the reaction zone. The generated heat may transfer from the reaction zone to a pyrolysis zone in the formation. The heat may transfer by conduction, radiation, and/or convection. A heated portion of the formation may include the reaction zone and the pyrolysis zone. The heated portion may also be located adjacent to the opening. One or more of the conduits may remove one or more oxidation products from the reaction zone and/or the opening in the formation. Alternatively, additional conduits may remove one or more oxidation products from the reaction zone and/or formation.
In certain embodiments, the flow of oxidizing fluid may be controlled along at least a portion of the length of the reaction zone. In some embodiments, hydrogen may be allowed to transfer into the reaction zone.
In an embodiment, a system and a method may include an opening in the formation extending from a first location on the surface of the earth to a second location on the surface of the earth. For example, the opening may be substantially U-shaped. Heat sources may be placed within the opening to provide heat to at least a portion of the formation.
A conduit may be positioned in the opening extending from the first location to the second location. In an embodiment, a heat source may be positioned proximate and/or in the conduit to provide heat to the conduit. Transfer of the heat through the conduit may provide heat to a selected section of the formation. In some embodiments, an additional heater may be placed in an additional conduit to provide heat to the selected section of the formation through the additional conduit.
In some embodiments, an annulus is formed between a wall of the opening and a wall of the conduit placed within the opening extending from the first location to the second location. A heat source may be place proximate and/or in the annulus to provide heat to a portion the opening. The provided heat may transfer through the annulus to a selected section of the formation.
In an embodiment, a system and method for heating a relatively low permeability formation containing heavy hydrocarbons may include one or more insulated conductors disposed in one or more openings in the formation. The openings may be uncased. Alternatively, the openings may include a casing. As such, the insulated conductors may provide conductive, radiant, or convective heat to at least a portion of the formation. In addition, the system and method may allow heat to transfer from the insulated conductor to a section of the formation. In some embodiments, the insulated conductor may include a copper-nickel alloy. In some embodiments, the insulated conductor may be electrically coupled to two additional insulated conductors in a 3-phase Y configuration.
An embodiment of a system and method for heating a relatively low permeability formation containing heavy hydrocarbons may include a conductor placed within a conduit (e.g., a conductor-in-conduit heat source). The conduit may be disposed within the opening. An electric current may be applied to the conductor to provide heat to a portion of the formation. The system may allow heat to transfer from the conductor to a section of the formation during use. In some embodiments, an oxidizing fluid source may be placed proximate an opening in the formation extending from the first location on the earth""s surface to the second location on the earth""s surface. The oxidizing fluid source may provide oxidizing fluid to a conduit in the opening. The oxidizing fluid may transfer from the conduit to a reaction zone in the formation. In an embodiment, an electrical current may be provided to the conduit to heat a portion of the conduit. The heat may transfer to the reaction zone in the relatively low permeability formation containing heavy hydrocarbons. Oxidizing fluid may then be provided to the conduit. The oxidizing fluid may oxidize hydrocarbons in the reaction zone, thereby generating heat. The generated heat may transfer to a pyrolysis zone and the transferred heat may pyrolyze hydrocarbons within the pyrolysis zone.
In some embodiments, an insulation layer may be coupled to a portion of the conductor. The insulation layer may electrically insulate at least a portion of the conductor from the conduit during use.
In an embodiment, a conductor-in-conduit heat source having a desired length may be assembled. A conductor may be placed within the conduit to form the conductor-in-conduit heat source. Two or more conductor-in-conduit heat sources may be coupled together to form a heat source having the desired length. The conductors of the conductor-in-conduit heat sources may be electrically coupled together. In addition, the conduits may be electrically coupled together. A desired length of the conductor-in-conduit may be placed in an opening in the relatively low permeability formation containing heavy hydrocarbons. In some embodiments, individual sections of the conductor-in-conduit heat source may be coupled using shielded active gas welding.
In some embodiments, a centralizer may be used to inhibit movement of the conductor within the conduit. A centralizer may be placed on the conductor as a heat source is made. In certain embodiments, a protrusion may be placed on the conductor to maintain the location of a centralizer.
In certain embodiments, a heat source of a desired length may be assembled proximate the relatively low permeability formation containing heavy hydrocarbons. The assembled heat sources may then be coiled. The heat source may be placed in the relatively low permeability formation containing heavy hydrocarbons by uncoiling the heat source into the opening in the relatively low permeability formation containing heavy hydrocarbons.
In certain embodiments, portions of the conductors may include an electrically conductive material. Use of the electrically conductive material on a portion (e.g., in the overburden portion) of the conductor may lower an electrical resistance of the conductor.
A conductor placed in a conduit may be treated to increase the emissivity of the conductor, in some embodiments. The emissivity of the conductor may be increased by roughening at least a portion of the surface of the conductor. In certain embodiments, the conductor may be treated to increase the emissivity prior to being placed within the conduit. In some embodiments, the conduit may be treated to increase the emissivity of the conduit.
In an embodiment, a system and method may include one or more elongated members disposed in an opening in the formation. Each of the elongated members may provide heat to at least a portion of the formation. One or more conduits may be disposed in the opening. One or more of the conduits may provide an oxidizing fluid from an oxidizing fluid source into the opening. In certain embodiments, the oxidizing fluid may inhibit carbon deposition on or proximate the elongated member.
In certain embodiments, an expansion mechanism may be coupled to a heat source. The expansion mechanism may allow the heat source to move during use. For example, the expansion mechanism may allow for the expansion of the heat source during use.
In one embodiment, an in situ method and system for heating a relatively low permeability formation containing heavy hydrocarbons may include providing oxidizing fluid to a first oxidizer placed in an opening in the formation. Fuel may be provided to the first oxidizer and at least some fuel may be oxidized in the first oxidizer. Oxidizing fluid may be provided to a second oxidizer placed in the opening in the formation. Fuel may be provided to the second oxidizer and at least some fuel may be oxidized in the second oxidizer. Heat from oxidation of fuel may be allowed to transfer to a portion of the formation.
An opening in a relatively low permeability formation containing heavy hydrocarbons may include a first elongated portion, a second elongated portion, and a third elongated portion. Certain embodiments of a method and system for heating a relatively low permeability formation containing heavy hydrocarbons may include providing heat from a first heater placed in the second elongated portion. The second elongated portion may diverge from the first elongated portion in a first direction. The third elongated portion may diverge from the first elongated portion in a second direction. The first direction may be substantially different than the second direction. Heat may be provided from a second heater placed in the third elongated portion of the opening in the formation. Heat from the first heater and the second heater may be allowed to transfer to a portion of the formation.
An embodiment of a method and system for heating a relatively low permeability formation containing heavy hydrocarbons may include providing oxidizing fluid to a first oxidizer placed in an opening in the formation. Fuel may be provided to the first oxidizer and at least some fuel may be oxidized in the first oxidizer. The method may further include allowing heat from oxidation of fuel to transfer to a portion of the formation and allowing heat to transfer from a heater placed in the opening to a portion of the formation.
In an embodiment, a system and method for heating a relatively low permeability formation containing heavy hydrocarbons may include oxidizing a fuel fluid in a heater. The method may further include providing at least a portion of the oxidized fuel fluid into a conduit disposed in an opening in the formation. In addition, additional heat may be transferred from an electric heater disposed in the opening to the section of the formation. Heat may be allowed to transfer uniformly along a length of the opening.
Energy input costs may be reduced in some embodiments of systems and methods described above. For example, an energy input cost may be reduced by heating a portion of a relatively low permeability formation containing heavy hydrocarbons by oxidation in combination with heating the portion of the formation by an electric heater. The electric heater may be turned down and/or off when the oxidation reaction begins to provide sufficient heat to the formation. Electrical energy costs associated with heating at least a portion of a formation with an electric heater may be reduced. Thus, a more economical process may be provided for heating a relatively low permeability formation containing heavy hydrocarbons in comparison to heating by a conventional method. In addition, the oxidation reaction may be propagated slowly through a greater portion of the formation such that fewer heat sources may be required to heat such a greater portion in comparison to heating by a conventional method.
Certain embodiments as described herein may provide a lower cost system and method for heating a relatively low permeability formation containing heavy hydrocarbons. For example, certain embodiments may more uniformly transfer heat along a length of a heater. Such a length of a heater may be greater than about 300 m or possibly greater than about 600 m. In addition, in certain embodiments, heat may be provided to the formation more efficiently by radiation. Furthermore, certain embodiments of systems may have a substantially longer lifetime than presently available systems.
In an embodiment, an in situ conversion system and method for hydrocarbons may include maintaining a portion of the formation in a substantially unheated condition. The portion may provide structural strength to the formation and/or confinement/isolation to certain regions of the formation. A processed relatively low permeability formation containing heavy hydrocarbons may have alternating heated and substantially unheated portions arranged in a pattern that may, in some embodiments, resemble a checkerboard pattern, or a pattern of alternating areas (e.g., strips) of heated and unheated portions.
In an embodiment, a heat source may advantageously heat only along a selected portion or selected portions of a length of the heater. For example, a formation may include several hydrocarbon containing layers. One or more of the hydrocarbon containing layers may be separated by layers containing little or no hydrocarbons. A heat source may include several discrete high heating zones that may be separated by low heating zones. The high heating zones may be disposed proximate hydrocarbon containing layers such that the layers may be heated. The low heating zones may be disposed proximate layers containing little or no hydrocarbons such that the layers may not be substantially heated. For example, an electric heater may include one or more low resistance heater sections and one or more high resistance heater sections. Low resistance heater sections of the electric heater may be disposed in and/or proximate layers containing little or no hydrocarbons. In addition, high resistance heater sections of the electric heater may be disposed proximate hydrocarbon containing layers. In an additional example, a fueled heater (e.g., surface burner) may include insulated sections. Insulated sections of the fueled heater may be placed proximate or adjacent to layers containing little or no hydrocarbons. Alternately, a heater with distributed air and/or fuel may be configured such that little or no fuel may be combusted proximate or adjacent to layers containing little or no hydrocarbons. Such a fueled heater may include flameless combustors and natural distributed combustors.
In certain embodiments, the permeability of a relatively low permeability formation containing heavy hydrocarbons may vary within the formation. For example, a first section may have a lower permeability than a second section. In an embodiment, heat may be provided to the formation to pyrolyze hydrocarbons within the lower permeability first section. Pyrolysis products may be produced from the higher permeability second section in a mixture of hydrocarbons.
In an embodiment, a heating rate of the formation may be slowly raised through the pyrolysis temperature range. For example, an in situ conversion process for hydrocarbons may include heating at least a portion of a relatively low permeability formation containing heavy hydrocarbons to raise an average temperature of the portion above about 270xc2x0 C. by a rate less than a selected amount (e.g., about 10xc2x0 C., 5xc2x0 C., 3xc2x0 C., 1xc2x0 C., 0.5xc2x0 C., or 0.1xc2x0 C.) per day. In a further embodiment, the portion may be heated such that an average temperature of the selected section may be less than about 375xc2x0 C. or, in some embodiments, less than about 400xc2x0 C.
In an embodiment, a temperature of the portion may be monitored through a test well disposed in a formation. For example, the test well may be positioned in a formation between a first heat source and a second heat source. Certain systems and methods may include controlling the heat from the first heat source and/or the second heat source to raise the monitored temperature at the test well at a rate of less than about a selected amount per day. In addition or alternatively, a temperature of the portion may be monitored at a production well. An in situ conversion process for hydrocarbons may include controlling the heat from the first heat source and/or the second heat source to raise the monitored temperature at the production well at a rate of less than a selected amount per day.
An embodiment of an in situ method of measuring a temperature within a wellbore may include providing a pressure wave from a pressure wave source into the wellbore. The wellbore may include a plurality of discontinuities along a length of the wellbore. The method further includes measuring a reflection signal of the pressure wave and using the reflection signal to assess at least one temperature between at least two discontinuities.
Certain embodiments may include heating a selected volume of a relatively low permeability formation containing heavy hydrocarbons. Heat may be provided to the selected volume by providing power to one or more heat sources. Power may be defined as heating energy per day provided to the selected volume. A power (Pwr) required to generate a heating rate (h, in units of, for example, xc2x0 C./day) in a selected volume (V) of a relatively low permeability formation containing heavy hydrocarbons may be determined by EQN. 1:
Pwr=h*V*Cv*xcfx81B.xe2x80x83xe2x80x83(1) 
In this equation, an average heat capacity of the formation (Cv) and an average bulk density of the formation (xcfx81B) may be estimated or determined using one or more samples taken from the relatively low permeability formation containing heavy hydrocarbons.
Certain embodiments may include raising and maintaining a pressure in a relatively low permeability formation containing heavy hydrocarbons. Pressure may be, for example, controlled within a range of about 2 bars absolute to about 20 bars absolute. For example, the process may include controlling a pressure within a majority of a selected section of a heated portion of the formation. The controlled pressure may be above about 2 bars absolute during pyrolysis. In an alternate embodiment, an in situ conversion process for hydrocarbons may include raising and maintaining the pressure in the formation within a range of about 20 bars absolute to about 36 bars absolute.
In an embodiment, compositions and properties of formation fluids produced by an in situ conversion process for hydrocarbons may vary depending on, for example, conditions within a relatively low permeability formation containing heavy hydrocarbons.
Certain embodiments may include controlling the heat provided to at least a portion of the formation such that production of less desirable products in the portion may be inhibited. Controlling the heat provided to at least a portion of the formation may also increase the uniformity of permeability within the formation. For example, controlling the heating of the formation to inhibit production of less desirable products may, in some embodiments, include controlling the heating rate to less than a selected amount (e.g., 10xc2x0 C., 5xc2x0 C., 3xc2x0 C., 1xc2x0 C., 0.5xc2x0 C., or 0.1xc2x0 C.) per day.
Controlling pressure, heat and/or heating rates of a selected section in a formation may increase production of selected formation fluids. For example, the amount and/or rate of heating may be controlled to produce formation fluids having an American Petroleum Institute (xe2x80x9cAPIxe2x80x9d) gravity greater than about 25. Heat and/or pressure may be controlled to inhibit production of olefins in the produced fluids.
Controlling formation conditions to control the pressure of hydrogen in the produced fluid may result in improved qualities of the produced fluids. In some embodiments, it may be desirable to control formation conditions so that the partial pressure of hydrogen in a produced fluid is greater than about 0.5 bars absolute, as measured at a production well.
In one embodiment, a method of treating a relatively low permeability formation containing heavy hydrocarbons in situ may include adding hydrogen to the selected section after a temperature of the selected section is at least about 270xc2x0 C. Other embodiments may include controlling a temperature of the formation by selectively adding hydrogen to the formation.
In certain embodiments, a relatively low permeability formation containing heavy hydrocarbons may be treated in situ with a heat transfer fluid such as steam. In an embodiment, a method of formation may include injecting a heat transfer fluid into a formation. Heat from the heat transfer fluid may transfer to a selected section of the formation. The heat from the heat transfer fluid may pyrolyze a substantial portion of the hydrocarbons within the selected section of the formation. The produced gas mixture may include hydrocarbons with an average API gravity greater than about 25xc2x0.
Furthermore, treating a hydrocarbon-containing formation with a heat transfer fluid may also mobilize hydrocarbons in the formation. In an embodiment, a method of treating a formation may include injecting a heat transfer fluid into a formation, allowing the heat from the heat transfer fluid to transfer to a selected first section of the formation, and mobilizing and pyrolyzing at least some of the hydrocarbons within the selected first section of the formation. At least some of the mobilized hydrocarbons may flow from the selected first section of the formation to a selected second section of the formation. The heat may pyrolyze at least some of the hydrocarbons within the selected second section of the formation. A gas mixture may be produced from the formation.
Another embodiment of treating a formation with a heat transfer fluid may include a moving heat transfer fluid front. A method may include injecting a heat transfer fluid into a formation and allowing the heat transfer fluid to migrate through the formation. A size of a selected section may increase as a heat transfer fluid front migrates through an untreated portion of the formation. The selected section is a portion of the formation treated by the heat transfer fluid. Heat from the heat transfer fluid may transfer heat to the selected section. The heat may pyrolyze at least some of the hydrocarbons within the selected section of the formation. The heat may also mobilize at least some of the hydrocarbons at the heat transfer fluid front. The mobilized hydrocarbons may flow substantially parallel to the heat transfer fluid front. The heat may pyrolyze at least a portion of the hydrocarbons in the mobilized fluid and a gas mixture may be produced from the formation.
Simulations may be utilized to increase an understanding of in situ processes. Simulations may model heating of the formation from heat sources and the transfer of heat to a selected section of the formation. Simulations may require the input of model parameters, properties of the formation, operating conditions, process characteristics, and/or desired parameters to determine operating conditions. Simulations may assess various aspects of an in situ process. For example, various aspects may include, but not be limited to, deformation characteristics, heating rates, temperatures within the formation, pressures, time to first produced fluids, and/or compositions of produced fluids.
Systems utilized in conducting simulations may include a central processing unit (CPU), a data memory, and a system memory. The system memory and the data memory may be coupled to the CPU. Computer programs executable to implement simulations may be stored on the system memory. Carrier mediums may include program instructions that are computer-executable to simulate the in situ processes.
In one embodiment, a computer-implemented method and system of treating a relatively low permeability formation containing heavy hydrocarbons may include providing to a computational system at least one set of operating conditions of an in situ system being used to apply heat to a formation. The in situ system may include at least one heat source. The method may further include providing to the computational system at least one desired parameter for the in situ system. The computational system may be used to determine at least one additional operating condition of the formation to achieve the desired parameter.
In an embodiment, operating conditions may be determined by measuring at least one property of the formation. At least one measured property may be input into a computer executable program. At least one property of formation fluids selected to be produced from the formation may also be input into the computer executable program. The program may be operable to determine a set of operating conditions from at least the one or more measured properties. The program may also determine the set of operating conditions from at least one property of the selected formation fluids. The determined set of operating conditions may increase production of selected formation fluids from the formation.
In some embodiments, a property of the formation and an operating condition used in the in situ process may be provided to a computer system to model the in situ process to determine a process characteristic.
In an embodiment, a heat input rate for an in situ process from two or more heat sources may be simulated on a computer system. A desired parameter of the in situ process may be provided to the simulation. The heat input rate from the heat sources may be controlled to achieve the desired parameter.
Alternatively, a heat input property may be provided to a computer system to assess heat injection rate data using a simulation. In addition, a property of the formation may be provided to the computer system. The property and the heat injection rate data may be utilized by a second simulation to determine a process characteristic for the in situ process as a function of time.
Values for the model parameters may be adjusted using process characteristics from a series of simulations. The model parameters may be adjusted such that the simulated process characteristics correspond to process characteristics in situ. After the model parameters have been modified to correspond to the in situ process, a process characteristic or a set of process characteristics based on the modified model parameters may be determined. In certain embodiments, multiple simulations may be run such that the simulated process characteristics correspond to the process characteristics in situ.
In some embodiments, operating conditions may be supplied to a simulation to assess a process characteristic. Additionally, a desired value of a process characteristic for the in situ process may be provided to the simulation to assess an operating condition that yields the desired value.
In certain embodiments, databases in memory on a computer may be used to store relationships between model parameters, properties of the formation, operating conditions, process characteristics, desired parameters, etc. These databases may be accessed by the simulations to obtain inputs. For example, after desired values of process characteristics are provided to simulations, an operating condition may be assessed to achieve the desired values using these databases.
In some embodiments, computer systems may utilize inputs in a simulation to assess information about the in situ process. In some embodiments, the assessed information may be used to operate the in situ process. Alternatively, the assessed information and a desired parameter may be provided to a second simulation to obtain information. This obtained information may be used to operate the in situ process.
In an embodiment, a method of modeling may include simulating one or more stages of the in situ process. Operating conditions from the one or more stages may be provided to a simulation to assess a process characteristic of the one or more stages.
In an embodiment, operating conditions may be assessed by measuring at least one property of the formation. At least the measured properties may be input into a computer executable program. At least one property of formation fluids selected to be produced from the formation may also be input into the computer executable program. The program may be operable to assess a set of operating conditions from at least the one or more measured properties. The program may also determine the set of operating conditions from at least one property of the selected formation fluids. The assessed set of operating conditions may increase production of selected formation fluids from the formation.
In one embodiment, a method for controlling an in situ system of treating a relatively low permeability formation containing heavy hydrocarbons may include monitoring at least one acoustic event within the formation using at least one acoustic detector placed within a wellbore in the formation. At least one acoustic event may be recorded with an acoustic monitoring system. The method may also include analyzing the at least one acoustic event to determine at least one property of the formation. The in situ system may be controlled based on the analysis of the at least one acoustic event.
An embodiment of a method of determining a heating rate for treating a relatively low permeability formation containing heavy hydrocarbons in situ may include conducting an experiment at a relatively constant heating rate. The results of the experiment may be used to determine a heating rate for treating the formation in situ. The determined heating rate may be used to determine a well spacing in the formation.
In an embodiment, a method of predicting characteristics of a formation fluid may include determining an isothermal heating temperature that corresponds to a selected heating rate for the formation. The determined isothermal temperature may be used in an experiment to determine at least one product characteristic of the formation fluid produced from the formation for the selected heating rate. Certain embodiments may include altering a composition of formation fluids produced from a relatively low permeability formation containing heavy hydrocarbons by altering a location of a production well with respect to a heater well. For example, a production well may be located with respect to a heater well such that a non-condensable gas fraction of produced hydrocarbon fluids may be larger than a condensable gas fraction of the produced hydrocarbon fluids.
Condensable hydrocarbons produced from the formation will typically include paraffins, cycloalkanes, mono-aromatics, and di-aromatics as major components. Such condensable hydrocarbons may also include other components such as tri-aromatics, etc.
In certain embodiments, a majority of the hydrocarbons in produced fluid may have a carbon number of less than approximately 25. Alternatively, less than about 15 weight % of the hydrocarbons in the fluid may have a carbon number greater than approximately 25. In other embodiments, fluid produced may have a weight ratio of hydrocarbons having carbon numbers from 2 through 4, to methane, of greater than approximately 1. The non-condensable hydrocarbons may include, but are not limited to, hydrocarbons having carbon numbers less than 5.
In certain embodiments, the API gravity of the hydrocarbons in produced fluid may be approximately 25 or above (e.g., 30, 40, 50, etc.). In certain embodiments, the hydrogen to carbon atomic ratio in produced fluid may be at least approximately 1.7 (e.g., 1.8, 1.9, etc.).
Condensable hydrocarbons of a produced fluid may also include olefins. For example, the olefin content of the condensable hydrocarbons may be from about 0.1 weight % to about 15 weight %. Alternatively, the olefin content of the condensable hydrocarbons may be from about 0.1 weight % to about 2.5 weight % or, in some embodiments, less than about 5 weight %.
Non-condensable hydrocarbons of a produced fluid may also include olefins. For example, the olefin content of the non-condensable hydrocarbons may be gauged using the ethene/ethane molar ratio. In certain embodiments, the ethene/ethane molar ratio may range from about 0.001 to about 0.15.
Fluid produced from the formation may include aromatic compounds. For example, the condensable hydrocarbons may include an amount of aromatic compounds greater than about 20 weight % or about 25 weight % of the condensable hydrocarbons. The condensable hydrocarbons may also include relatively low amounts of compounds with more than two rings in them (e.g., tri-aromatics or above). For example, the condensable hydrocarbons may include less than about 1 weight %, 2 weight %, or about 5 weight % of tri-aromatics or above in the condensable hydrocarbons.
In particular, in certain embodiments, asphaltenes (i.e., large multi-ring aromatics that are substantially insoluble in hydrocarbons) make up less than about 0.1 weight % of the condensable hydrocarbons. For example, the condensable hydrocarbons may include an asphaltene component of from about 0.0 weight % to about 0.1 weight % or, in some embodiments, less than about 0.3 weight %.
Condensable hydrocarbons of a produced fluid may also include relatively large amounts of cycloalkanes. For example, the condensable hydrocarbons may include a cycloalkane component of up to 30 weight % (e.g., from about 5 weight % to about 30 weight %) of the condensable hydrocarbons.
In certain embodiments, the condensable hydrocarbons of the fluid produced from a formation may include compounds containing nitrogen. For example, less than about 1 weight % (when calculated on an elemental basis) of the condensable hydrocarbons is nitrogen (e.g., typically the nitrogen is in nitrogen containing compounds such as pyridines, amines, amides, etc.).
In certain embodiments, the condensable hydrocarbons of the fluid produced from a formation may include compounds containing oxygen. For example, in certain embodiments, less than about 1 weight % (when calculated on an elemental basis) of the condensable hydrocarbons is oxygen (e.g., typically the oxygen is in oxygen containing compounds such as phenols, substituted phenols, ketones, etc.).
In certain embodiments, the condensable hydrocarbons of the fluid produced from a formation may include compounds containing sulfur. For example, less than about 1 weight % (when calculated on an elemental basis) of the condensable hydrocarbons is sulfur (e.g., typically the sulfur is in sulfur containing compounds such as thiophenes, mercaptans, etc.).
Furthermore, the fluid produced from the formation may include ammonia (typically the ammonia condenses with the water, if any, produced from the formation). For example, the fluid produced from the formation may in certain embodiments include about 0.05 weight % or more of ammonia.
Furthermore, a produced fluid from the formation may also include molecular hydrogen (H2), water, carbon dioxide, hydrogen sulfide, etc. For example, the fluid may include a H2 content between about 10 volume % and about 80 volume % of the non-condensable hydrocarbons.
In an embodiment, an in situ conversion process for treating a relatively low permeability formation containing heavy hydrocarbons may include providing heat to a section of the formation to yield greater than about 60 weight % of the hydrocarbons.
Formation fluids produced from a section of the formation may contain one or more components that may be separated from the formation fluids. In addition, conditions within the formation may be controlled to increase production of a desired component.
In certain embodiments, a method of converting pyrolysis fluids into olefins may include converting formation fluids into olefins. An embodiment may include separating olefins from fluids produced from a formation.
An embodiment of a method of enhancing BTEX compounds (i.e., benzene, toluene, ethylbenzene, and xylene compounds) produced in situ in a relatively low permeability formation containing heavy hydrocarbons may include controlling at least one condition within a portion of the formation to enhance production of BTEX compounds in formation fluid. In another embodiment, a method may include separating at least a portion of the BTEX compounds from the formation fluid. In addition, the BTEX compounds may be separated from the formation fluids after the formation fluids are produced. In other embodiments, at least a portion of the produced formation fluids may be converted into BTEX compounds.
In one embodiment, a method of enhancing naphthalene production from an in situ relatively low permeability formation containing heavy hydrocarbons may include controlling at least one condition within at least a portion of the formation to enhance production of naphthalene in formation fluid. In another embodiment, naphthalene may be separated from produced formation fluids.
Certain embodiments of a method of enhancing anthracene production from an in situ relatively low permeability formation containing heavy hydrocarbons may include controlling at least one condition within at least a portion of the formation to enhance production of anthracene in formation fluid. In an embodiment, anthracene may be separated from produced formation fluids.
In one embodiment, a method of separating ammonia from fluids produced from an in situ relatively low permeability formation containing heavy hydrocarbons may include separating at least a portion of the ammonia from the produced fluid. Furthermore, an embodiment of a method of generating ammonia from fluids produced from a formation may include hydrotreating at least a portion of the produced fluids to generate ammonia.
In an embodiment, a method of enhancing pyridines production from an in situ relatively low permeability formation containing heavy hydrocarbons may include controlling at least one condition within at least a portion of the formation to enhance production of pyridines in formation fluid. Additionally, pyridines may be separated from produced formation fluids.
In certain embodiments, a method of selecting a relatively low permeability formation containing heavy hydrocarbons to be treated in situ such that production of pyridines is enhanced may include examining pyridines concentrations in a plurality of samples from relatively low permeability formations containing heavy hydrocarbons. The method may further include selecting a formation for treatment at least partially based on the pyridines concentrations. Consequently, the production of pyridines to be produced from the formation may be enhanced.
In an embodiment, a method of enhancing pyrroles production from an in situ relatively low permeability formation containing heavy hydrocarbons may include controlling at least one condition within at least a portion of the formation to enhance production of pyrroles in formation fluid. In addition, pyrroles may be separated from produced formation fluids.
In certain embodiments, a relatively low permeability formation containing heavy hydrocarbons to be treated in situ may be selected such that production of pyrroles is enhanced. The method may include examining pyrroles concentrations in a plurality of samples from relatively low permeability formations containing heavy hydrocarbons. The formation may be selected for treatment at least partially based on the pyrroles concentrations, thereby enhancing the production of pyrroles to be produced from such formation.
In one embodiment, thiophenes production from an in situ relatively low permeability formation containing heavy hydrocarbons may be enhanced by controlling at least one condition within at least a portion of the formation to enhance production of thiophenes in formation fluid. Additionally, the thiophenes may be separated from produced formation fluids.
An embodiment of a method of selecting a relatively low permeability formation containing heavy hydrocarbons to be treated in situ such that production of thiophenes is enhanced may include examining thiophenes concentrations in a plurality of samples from relatively low permeability formations containing heavy hydrocarbons. The method may further include selecting a formation for treatment at least partially based on the thiophenes concentrations, thereby enhancing the production of thiophenes from such formations.
Certain embodiments may include providing a reducing agent to at least a portion of the formation. A reducing agent provided to a portion of the formation during heating may increase production of selected formation fluids. A reducing agent may include, but is not limited to, molecular hydrogen. For example, pyrolyzing at least some hydrocarbons in a relatively low permeability formation containing heavy hydrocarbons may include forming hydrocarbon fragments. Such hydrocarbon fragments may react with each other and other compounds present in the formation. Reaction of these hydrocarbon fragments may increase production of olefin and aromatic compounds from the formation. Therefore, a reducing agent provided to the formation may react with hydrocarbon fragments to form selected products and/or inhibit the production of non-selected products.
In an embodiment, a hydrogenation reaction between a reducing agent provided to a relatively low permeability formation containing heavy hydrocarbons and at least some of the hydrocarbons within the formation may generate heat. The generated heat may be allowed to transfer such that at least a portion of the formation may be heated. A reducing agent such as molecular hydrogen may also be autogenously generated within a portion of a relatively low permeability formation containing heavy hydrocarbons during an in situ conversion process for hydrocarbons. The autogenously generated molecular hydrogen may hydrogenate formation fluids within the formation. Allowing formation waters to contact hot carbon in the spent formation may generate molecular hydrogen. Cracking an injected hydrocarbon fluid may also generate molecular hydrogen.
Certain embodiments may also include providing a fluid produced in a first portion of a relatively low permeability formation containing heavy hydrocarbons to a second portion of the formation. A fluid produced in a first portion of a relatively low permeability formation containing heavy hydrocarbons may be used to produce a reducing environment in a second portion of the formation. For example, molecular hydrogen generated in a first portion of a formation may be provided to a second portion of the formation. Alternatively, at least a portion of formation fluids produced from a first portion of the formation may be provided to a second portion of the formation to provide a reducing environment within the second portion.
In an embodiment, a method for hydrotreating a compound in a heated formation in situ may include controlling the H2 partial pressure in a selected section of the formation, such that sufficient H2 may be present in the selected section of the formation for hydrotreating. The method may further include providing a compound for hydrotreating to at least the selected section of the formation and producing a mixture from the formation that includes at least some of the hydrotreated compound.
In certain embodiments, a mass of at least a portion of the formation may be reduced due, for example, to the production of formation fluids from the formation. As such, a permeability and porosity of at least a portion of the formation may increase. In addition, removing water during the heating may also increase the permeability and porosity of at least a portion of the formation.
Certain embodiments may include increasing a permeability of at least a portion of a relatively low permeability formation containing heavy hydrocarbons to greater than about 0.01, 0.1, 1, 10, 20, and/or 50 darcy. In addition, certain embodiments may include substantially uniformly increasing a permeability of at least a portion of a relatively low permeability formation containing heavy hydrocarbons. Some embodiments may include increasing a porosity of at least a portion of a relatively low permeability formation containing heavy hydrocarbons substantially uniformly.
Certain systems and methods may be used to treat heavy hydrocarbons in at least a portion of a relatively low permeability formation (e.g., in xe2x80x9ctightxe2x80x9d formations that contain heavy hydrocarbons). Such heavy hydrocarbons may be heated to pyrolyze at least some of the heavy hydrocarbons in a selected section of the formation. Heating may also increase the permeability of at least a portion of the selected section. Fluids generated from pyrolysis may be produced from the formation.
Certain embodiments for treating heavy hydrocarbons in a relatively low permeability formation may include providing heat from one or more heat sources to pyrolyze some of the heavy hydrocarbons and then to vaporize a portion of the heavy hydrocarbons. The heat sources may pyrolyze at least some heavy hydrocarbons in a selected section of the formation and may pressurize at least a portion of the selected section. During the heating, the pressure within the formation may increase substantially. The pressure in the formation may be controlled such that the pressure in the formation may be maintained to produce a fluid of a desired composition. Pyrolyzation fluid may be removed from the formation as vapor from one or more heater wells by using the back pressure created by heating the formation.
Certain embodiments for treating heavy hydrocarbons in at least a portion of a relatively low permeability formation may include heating to create a pyrolysis zone and heating a selected second section to less than the average temperature within the pyrolysis zone. Heavy hydrocarbons may be pyrolyzed in the pyrolysis zone. Heating the selected second section may decrease the viscosity of some of the heavy hydrocarbons in the selected second section to create a low viscosity zone. The decrease in viscosity of the fluid in the selected second section may be sufficient such that at least some heated heavy hydrocarbons within the selected second section may flow into the pyrolysis zone. Pyrolyzation fluid may be produced from the pyrolysis zone. In one embodiment, the density of the heat sources in the pyrolysis zone may be greater than in the low viscosity zone.
In certain embodiments, it may be desirable to create the pyrolysis zones and low viscosity zones sequentially over time. The heat sources in a region near a desired pyrolysis zone may be activated first, resulting in establishment of a substantially uniform pyrolysis zone after a period of time. Once the pyrolysis zone is established, heat sources in the low viscosity zone may be activated sequentially from nearest to farthest from the pyrolysis zone.
A heated formation may also be used to produce synthesis gas. Synthesis gas may be produced from the formation prior to or subsequent to producing a formation fluid from the formation. For example, synthesis gas generation may be commenced before and/or after formation fluid production decreases to an uneconomical level. Heat provided to pyrolyze hydrocarbons within the formation may also be used to generate synthesis gas. For example, if a portion of the formation is at a temperature from approximately 270xc2x0 C. to approximately 375xc2x0 C. (or 400xc2x0 C. in some embodiments) after pyrolyzation, then less additional heat is generally required to heat such portion to a temperature sufficient to support synthesis gas generation.
In certain embodiments, synthesis gas is produced after production of pyrolysis fluids. For example, after pyrolysis of a portion of a formation, synthesis gas may be produced from carbon and/or hydrocarbons remaining within the formation. Pyrolysis of the portion may produce a relatively high, substantially uniform permeability throughout the portion. Such a relatively high, substantially uniform permeability may allow generation of synthesis gas from a significant portion of the formation at relatively low pressures. The portion may also have a large surface area and/or surface area/volume. The large surface area may allow synthesis gas producing reactions to be substantially at equilibrium conditions during synthesis gas generation. The relatively high, substantially uniform permeability may result in a relatively high recovery efficiency of synthesis gas, as compared to synthesis gas generation in a relatively low permeability formation containing heavy hydrocarbons that has not been so treated.
Pyrolysis of at least some hydrocarbons may in some embodiments convert about 15 weight % or more of the carbon initially available. Synthesis gas generation may convert approximately up to an additional 80 weight % or more of carbon initially available within the portion. In situ production of synthesis gas from a relatively low permeability formation containing heavy hydrocarbons may allow conversion of larger amounts of carbon initially available within the portion. The amount of conversion achieved may, in some embodiments, be limited by subsidence concerns.
Certain embodiments may include providing heat from one or more heat sources to heat the formation to a temperature sufficient to allow synthesis gas generation (e.g., in a range of approximately 400xc2x0 C. to approximately 1200xc2x0 C. or higher). At a lower end of the temperature range, generated synthesis gas may have a high hydrogen (H2) to carbon monoxide (CO) ratio. At an upper end of the temperature range, generated synthesis gas may include mostly H2 and CO in lower ratios (e.g., approximately a 1:1 ratio).
Heat sources for synthesis gas production may include any of the heat sources as described in any of the embodiments set forth herein. Alternatively, heating may include transferring heat from a heat transfer fluid (e.g., steam or combustion products from a burner) flowing within a plurality of wellbores within the formation.
A synthesis gas generating fluid (e.g., liquid water, steam, carbon dioxide, air, oxygen, hydrocarbons, and mixtures thereof) may be provided to the formation. For example, the synthesis gas generating fluid mixture may include steam and oxygen. In an embodiment, a synthesis gas generating fluid may include aqueous fluid produced by pyrolysis of at least some hydrocarbons within one or more other portions of the formation. Providing the synthesis gas generating fluid may alternatively include raising a water table of the formation to allow water to flow into it. Synthesis gas generating fluid may also be provided through at least one injection wellbore. The synthesis gas generating fluid will generally react with carbon in the formation to form H2, water, methane, CO2, and/or CO. A portion of the carbon dioxide may react with carbon in the formation to generate carbon monoxide. Hydrocarbons such as ethane may be added to a synthesis gas generating fluid. When introduced into the formation, the hydrocarbons may crack to form hydrogen and/or methane. The presence of methane in produced synthesis gas may increase the heating value of the produced synthesis gas.
Synthesis gas generation is, in some embodiments, an endothermic process. Additional heat may be added to the formation during synthesis gas generation to maintain a high temperature within the formation. The heat may be added from heater wells and/or from oxidizing carbon and/or hydrocarbons within the formation.
In an embodiment, an oxidant may be added to a synthesis gas generating fluid. The oxidant may include, but is not limited to, air, oxygen enriched air, oxygen, hydrogen peroxide, other oxidizing fluids, or combinations thereof. The oxidant may react with carbon within the formation to exothermically generate heat. Reaction of an oxidant with carbon in the formation may result in production of CO2 and/or CO. Introduction of an oxidant to react with carbon in the formation may economically allow raising the formation temperature high enough to result in generation of significant quantities of H2 and CO from hydrocarbons within the formation. Synthesis gas generation may be via a batch process or a continuous process.
Synthesis gas may be produced from the formation through one or more producer wells that include one or more heat sources. Such heat sources may operate to promote production of the synthesis gas with a desired composition.
Certain embodiments may include monitoring a composition of the produced synthesis gas and then controlling heating and/or controlling input of the synthesis gas generating fluid to maintain the composition of the produced synthesis gas within a desired range. For example, in some embodiments (e.g., such as when the synthesis gas will be used as a feedstock for a Fischer-Tropsch process), a desired composition of the produced synthesis gas may have a ratio of hydrogen to carbon monoxide of about 1.8:1 to 2.2:1 (e.g., about 2:1 or about 2.1:1). In some embodiments (such as when the synthesis gas will be used as a feedstock to make methanol), such ratio may be about 3:1 (e.g., about 2.8:1 to 3.2:1).
Certain embodiments may include blending a first synthesis gas with a second synthesis gas to produce synthesis gas of a desired composition. The first and the second synthesis gases may be produced from different portions of the formation.
Synthesis gases may be converted to heavier condensable hydrocarbons. For example, a Fischer-Tropsch hydrocarbon synthesis process may convert synthesis gas to branched and unbranched paraffins. Paraffins produced from the Fischer-Tropsch process may be used to produce other products such as diesel, jet fuel, and naphtha products. The produced synthesis gas may also be used in a catalytic methanation process to produce methane. Alternatively, the produced synthesis gas may be used for production of methanol, gasoline and diesel fuel, ammonia, and middle distillates. Produced synthesis gas may be used to heat the formation as a combustion fuel. Hydrogen in produced synthesis gas may be used to upgrade oil.
Synthesis gas may also be used for other purposes. Synthesis gas may be combusted as fuel. Synthesis gas may also be used for synthesizing a wide range of organic and/or inorganic compounds, such as hydrocarbons and ammonia. Synthesis gas may be used to generate electricity by combusting it as a fuel, by reducing the pressure of the synthesis gas in turbines, and/or using the temperature of the synthesis gas to make steam (and then run turbines). Synthesis gas may also be used in an energy generation unit such as a molten carbonate fuel cell, a solid oxide fuel cell, or other type of fuel cell.
Certain embodiments may include separating a fuel cell feed stream from fluids produced from pyrolysis of at least some of the hydrocarbons within a formation. The fuel cell feed stream may include H2, hydrocarbons, and/or carbon monoxide. In addition, certain embodiments may include directing the fuel cell feed stream to a fuel cell to produce electricity. The electricity generated from the synthesis gas or the pyrolyzation fluids in the fuel cell may power electric heaters, which may heat at least a portion of the formation. Certain embodiments may include separating carbon dioxide from a fluid exiting the fuel cell. Carbon dioxide produced from a fuel cell or a formation may be used for a variety of purposes.
In certain embodiments, synthesis gas produced from a heated formation may be transferred to an additional area of the formation and stored within the additional area of the formation for a length of time. The conditions of the additional area of the formation may inhibit reaction of the synthesis gas. The synthesis gas may be produced from the additional area of the formation at a later time.
In some embodiments, treating a formation may include injecting fluids into the formation. The method may include providing heat to the formation, allowing the heat to transfer to a selected section of the formation, injecting a fluid into the selected section, and producing another fluid from the formation. Additional heat may be provided to at least a portion of the formation, and the additional heat may be allowed to transfer from at least the portion to the selected section of the formation. At least some hydrocarbons may be pyrolyzed within the selected section and a mixture may be produced from the formation. Another embodiment may include leaving a section of the formation proximate the selected section substantially unleached. The unleached section may inhibit the flow of water into the selected section.
In an embodiment, heat may be provided to the formation. The heat may be allowed to transfer to a selected section of the formation such that dissociation of carbonate minerals is inhibited. At least some hydrocarbons may be pyrolyzed within the selected section and a mixture produced from the formation. The method may further include reducing a temperature of the selected section and injecting a fluid into the selected section. Another fluid may be produced from the formation. Alternatively, subsequent to providing heat and allowing heat to transfer, a method may include injecting a fluid into the selected section and producing another fluid from the formation. Similarly, a method may include injecting a fluid into the selected section and pyrolyzing at least some hydrocarbons within the selected section of the formation after providing heat and allowing heat to transfer to the selected section.
In an embodiment that includes injecting fluids, a method of treating a formation may include providing heat from one or more heat sources and allowing the heat to transfer to a selected section of the formation such that a temperature of the selected section is less than about a temperature at which nahcolite dissociates. A fluid may be injected into the selected section and another fluid may be produced from the formation. The method may further include providing additional heat to the formation, allowing the additional heat to transfer to the selected section of the formation, and pyrolyzing at least some hydrocarbons within the selected section. A mixture may then be produced from the formation.
Certain embodiments that include injecting fluids may also include controlling the heating of the formation. A method may include providing heat to the formation, controlling the heat such that a selected section is at a first temperature, injecting a fluid into the selected section, and producing another fluid from the formation. The method may further include controlling the heat such that the selected section is at a second temperature that is greater than the first temperature. Heat may be allowed to transfer from the selected section, and at least some hydrocarbons may be pyrolyzed within the selected section of the formation. A mixture may be produced from the formation.
A further embodiment that includes injecting fluids may include providing heat to a formation, allowing the heat to transfer to a selected section of the formation, injecting a first fluid into the selected section, and producing a second fluid from the formation. The method may further include providing additional heat, allowing the additional heat to transfer to the selected section of the formation, pyrolyzing at least some hydrocarbons within the selected section of the formation, and producing a mixture from the formation. In addition, a temperature of the selected section may be reduced and a third fluid may be injected into the selected section. A fourth fluid may be produced from the formation.
In some embodiments, migration of fluids into and/or out of a treatment area may be inhibited. Inhibition of migration of fluids may occur before, during, and/or after an in situ treatment process. For example, migration of fluids may be inhibited while heat is provided from one or more heat sources to at least a portion of the treatment area. The heat may be allowed to transfer to at least a portion of the treatment area. Fluids may be produced from the treatment area.
Barriers may be used to inhibit migration of fluids into and/or out of a treatment area in a formation. Barriers may include, but are not limited to naturally occurring portions (e.g., overburden and/or underburden), frozen barrier zones, low temperature barrier zones, grout walls, sulfur wells, dewatering wells, and/or injection wells. Barriers may define the treatment area. Alternatively, barriers may be provided to a portion of the treatment area.
In an embodiment, a method of treating a relatively low permeability formation containing heavy hydrocarbons in situ may include providing a refrigerant to a plurality of barrier wells to form a low temperature barrier zone. The method may further include establishing a low temperature barrier zone. In some embodiments, the temperature within the low temperature barrier zone may be lowered to inhibit the flow of water into or out of at least a portion of a treatment area in the formation.
Certain embodiments of treating a relatively low permeability formation containing heavy hydrocarbons in situ may include providing a refrigerant to a plurality of barrier wells to form a frozen barrier zone. The frozen barrier zone may inhibit migration of fluids into and/or out of the treatment area In certain embodiments, a portion of the treatment area is below a water table of the formation. In addition, the method may include controlling pressure to maintain a fluid pressure within the treatment area above a hydrostatic pressure of the formation and producing a mixture of fluids from the formation.
Barriers may be provided to a portion of the formation prior to, during, and after providing heat from one or more heat sources to the treatment area. For example, a barrier may be provided to a portion of the formation that has previously undergone a conversion process.
Fluid may be introduced to a portion of the formation that has previously undergone an in situ conversion process. The fluid may be produced from the formation in a mixture, which may contain additional fluids present in the formation. In some embodiments, the produced mixture may be provided to an energy producing unit.
In some embodiments, one or more conditions in a selected section may be controlled during an in situ conversion process to inhibit formation of carbon dioxide. Conditions may be controlled to produce fluids having a carbon dioxide emission level that is less than a selected carbon dioxide level. For example, heat provided to the formation may be controlled to inhibit generation of carbon dioxide, while increasing production of molecular hydrogen.
In a similar manner, a method for producing methane from a relatively low permeability formation containing heavy hydrocarbons in situ while minimizing production of CO2 may include controlling the heat from the one or more heat sources to enhance production of methane in the produced mixture and generating heat via at least one or more of the heat sources in a manner that minimizes CO2 production. The methane may further include controlling a temperature proximate the production wellbore at or above a decomposition temperature of ethane.
In certain embodiments, a method for producing products from a heated formation may include controlling a condition within a selected section of the formation to produce a mixture having a carbon dioxide emission level below a selected baseline carbon dioxide emission level. In some embodiments, the mixture may be blended with a fluid to generate a product having a carbon dioxide emission level below the baseline.
In an embodiment, a method for producing methane from a heated formation in situ may include providing heat from one or more heat sources to at least one portion of the formation and allowing the heat to transfer to a selected section of the formation. The method may further include providing hydrocarbon compounds to at least the selected section of the formation and producing a mixture including methane from the hydrocarbons in the formation.
One embodiment of a method for producing hydrocarbons in a heated formation may include forming a temperature gradient in at least a portion of a selected section of the heated formation and providing a hydrocarbon mixture to at least the selected section of the formation. A mixture may then be produced from a production well.
In certain embodiments, a method for upgrading hydrocarbons in a heated formation may include providing hydrocarbons to a selected section of the heated formation and allowing the hydrocarbons to crack in the heated formation. The cracked hydrocarbons may be a higher grade than the provided hydrocarbons. The upgraded hydrocarbons may be produced from the formation.
Cooling a portion of the formation after an in situ conversion process may provide certain benefits, such as increasing the strength of the rock in the formation (thereby mitigating subsidence), increasing absorptive capacity of the formation, etc.
In an embodiment, a portion of a formation that has been pyrolyzed and/or subjected to synthesis gas generation may be allowed to cool or may be cooled to form a cooled, spent portion within the formation. For example, a heated portion of a formation may be allowed to cool by transference of heat to an adjacent portion of the formation. The transference of heat may occur naturally or may be forced by the introduction of heat transfer fluids through the heated portion and into a cooler portion of the formation.
In alternate embodiments, recovering thermal energy from a post treatment relatively low permeability formation containing heavy hydrocarbons may include injecting a heat recovery fluid into a portion of the formation. Heat from the formation may transfer to the heat recovery fluid. The heat recovery fluid may be produced from the formation. For example, introducing water to a portion of the formation may cool the portion. Water introduced into the portion may be removed from the formation as steam. The removed steam or hot water may be injected into a hot portion of the formation to create synthesis gas
In an embodiment, hydrocarbons may be recovered from a post treatment relatively low permeability formation containing heavy hydrocarbons by injecting a heat recovery fluid into a portion of the formation. Heat may vaporize at least some of the heat recovery fluid and at least some hydrocarbons in the formation. A portion of the vaporized recovery fluid and the vaporized hydrocarbons may be produced from the formation.
In certain embodiments, fluids in the formation may be removed from a post treatment hydrocarbon formation by injecting a heat recovery fluid into a portion of the formation. Heat may transfer to the heat recovery fluid and a portion of the fluid may be produced from the formation. The heat recovery fluid produced from the formation may include at least some of the fluids in the formation.
In one embodiment, a method of recovering excess heat from a heated formation may include providing a product stream to the heated formation, such that heat transfers from the heated formation to the product stream. The method may further include producing the product stream from the heated formation and directing the product stream to a processing unit. The heat of the product stream may then be transferred to the processing unit. In an alternate method for recovering excess heat from a heated formation the heated product stream may be directed to another formation, such that heat transfers from the product stream to the other formation.
In one embodiment, a method of utilizing heat of a heated formation may include placing a conduit in the formation, such that conduit input may be located separately from conduit output. The conduit may be heated by the heated formation to produce a region of reaction in at least a portion of the conduit. The method may further include directing a material through the conduit to the region of reaction. The material may undergo change in the region of reaction. A product may be produced from the conduit.
An embodiment of a method of utilizing heat of a heated formation may include providing heat from one or more heat sources to at least one portion of the formation and allowing the heat to transfer to a region of reaction in the formation. Material may be directed to the region of reaction and allowed to react in the region of reaction. A mixture may then be produced from the formation.
In an embodiment, a portion of a relatively low permeability formation containing heavy hydrocarbons may be used to store and/or sequester materials (e.g., formation fluids, carbon dioxide). The conditions within the portion of the formation may inhibit reactions of the materials. Materials may be may be stored in the portion for a length of time. In addition, materials may be produced from the portion at a later time. Materials stored within the portion may have been previously produced from the portion of the formation, and/or another portion of the formation.
After an in situ conversion process has been completed in a portion of the formation, fluid may be sequestered within the formation. In some embodiments, to store a significant amount of fluid within the formation, a temperature of the formation will often need to be less than about 100xc2x0 C. Water may be introduced into at least a portion of the formation to generate steam and reduce a temperature of the formation. The steam may be removed from the formation. The steam may be utilized for various purposes, including, but not limited to, heating another portion of the formation, generating synthesis gas in an adjacent portion of the formation, generating electricity, and/or as a steam flood in a oil reservoir. After the formation has cooled, fluid (e.g., carbon dioxide) may be pressurized and sequestered in the formation. Sequestering fluid within the formation may result in a significant reduction or elimination of fluid that is released to the environment due to operation of the in situ conversion process.
In alternate embodiments, carbon dioxide may be injected under pressure into the portion of the formation. The injected carbon dioxide may adsorb onto hydrocarbons in the formation and/or reside in void spaces such as pores in the formation. The carbon dioxide may be generated during pyrolysis, synthesis gas generation, and/or extraction of useful energy. In some embodiments, carbon dioxide may be stored in relatively deep hydrocarbon containing formations and used to desorb methane.
In one embodiment, a method for sequestering carbon dioxide in a heated formation may include precipitating carbonate compounds from carbon dioxide provided to a portion of the formation. In some embodiments, the portion may have previously undergone an in situ conversion process. Carbon dioxide and a fluid may be provided to the portion of the formation. The fluid may combine with carbon dioxide in the portion to precipitate carbonate compounds.
In an alternate embodiment, methane may be recovered from a hydrocarbon containing formation by providing heat to the formation. The heat may desorb a substantial portion of the methane within the selected section of the formation. At least a portion of the methane may be produced from the formation.
In an embodiment, a method for purifying water in a spent formation may include providing water to the formation and filtering the provided water in the formation. The filtered water may then be produced from the formation.
In an embodiment, treating a relatively low permeability formation containing heavy hydrocarbons in situ may include injecting a recovery fluid into the formation. Heat may be provided from one or more heat sources to the formation. The heat may transfer from one or more of the heat sources to a selected section of the formation and vaporize a substantial portion of recovery fluid in at least a portion of the selected section. The heat from the heat sources and the vaporized recovery fluid may pyrolyze at least some hydrocarbons within the selected section. A gas mixture may be produced from the formation. The produced gas mixture may include hydrocarbons with an average API gravity greater than about 25xc2x0.
In certain embodiments, a method of shutting-in an in situ treatment process in a relatively low permeability formation containing heavy hydrocarbons may include terminating heating from one or more heat sources providing heat to a portion of the formation. A pressure may be monitored and controlled in at least a portion of the formation. The pressure may be maintained approximately below a fracturing or breakthrough pressure of the formation.
One embodiment of a method of shutting-in an in situ treatment process in a relatively low permeability formation containing heavy hydrocarbons may include terminating heating from one or more heat sources providing heat to a portion of the formation. Hydrocarbon vapor may be produced from the formation. At least a portion of the produced hydrocarbon vapor may be injected into a portion of a storage formation. The hydrocarbon vapor may be injected into a relatively high temperature formation. A substantial portion of injected hydrocarbons may be converted to coke and H2 in the relatively high temperature formation. Alternatively, the hydrocarbon vapor may be stored in a depleted formation.